U.S. patent number 5,130,950 [Application Number 07/525,268] was granted by the patent office on 1992-07-14 for ultrasonic measurement apparatus.
This patent grant is currently assigned to Schlumberger Technology Corporation. Invention is credited to James C. Mayes, Jacques Orban.
United States Patent |
5,130,950 |
Orban , et al. |
July 14, 1992 |
Ultrasonic measurement apparatus
Abstract
Pulse echo apparatus and methods are disclosed for measuring
characteristics of a borehole while it is being drilled. A
component of a bottomhole assembly, preferably a drilling collar,
is provided with one or more ultra-sonic transceivers. A pulse echo
sensor of the transceiver is preferably placed in a stabilizer fin
of the collar, but may also be placed in the wall of the collar,
preferably close to a stabilizing fin. Electronic processing and
control circuitry for the pulse-echo sensor is provided in an
electronic module placed within such collar. Such pulse echo
apparatus, which preferably includes two diametrically opposed
transceivers, generates signals from which standoff from a borehole
wall may be determined. A method and apparatus are provided for
measuring standoff and borehole diameter in the presence of
drilling cuttings entrained in the drilling fluid. In a preferred
embodiment, such signals are assessed by the electronic processing
and control circuity to determine if gas has entered borehole.
Three methods and apparatus are provided for such gas entry
determination. The first relies on measurement of sonic impedance
of the drilling fluid by assessing the amplitude of an echo from an
interface between the drilling fluid and a delay-line placed
outwardly of a ceramic sensor. The second relies on measurement of
drilling fluid attenuation of a borehole wall echo. The third
relies on measurement of the phase of oscillations of echoes to
identify large gas bubbles entries. The pulse-echo sensor includes
a sensor stack including a backing element, a piezo-electric
ceramic disk, and a delay-line.
Inventors: |
Orban; Jacques (Sugar Land,
TX), Mayes; James C. (Sugar Land, TX) |
Assignee: |
Schlumberger Technology
Corporation (Houston, TX)
|
Family
ID: |
24092572 |
Appl.
No.: |
07/525,268 |
Filed: |
May 16, 1990 |
Current U.S.
Class: |
367/34; 250/254;
367/25; 367/86; 73/152.19; 73/152.58; 181/102; 367/35 |
Current CPC
Class: |
G01N
29/032 (20130101); G01B 17/06 (20130101); E21B
21/08 (20130101); G01V 1/52 (20130101); B06B
1/0681 (20130101); G01N 29/024 (20130101); G01N
29/28 (20130101); E21B 47/107 (20200501); G01N
29/02 (20130101); E21B 47/085 (20200501); G01B
17/00 (20130101); G01H 15/00 (20130101); G01N
29/222 (20130101); G01N 2291/02416 (20130101); G01N
2291/015 (20130101); G01N 2291/02433 (20130101); G01N
2291/018 (20130101); G01N 2291/012 (20130101); G01N
2291/011 (20130101) |
Current International
Class: |
E21B
47/10 (20060101); G01H 15/00 (20060101); E21B
47/00 (20060101); G01N 29/02 (20060101); E21B
21/08 (20060101); E21B 47/08 (20060101); E21B
21/00 (20060101); G01N 29/22 (20060101); G01B
17/00 (20060101); G01V 001/40 () |
Field of
Search: |
;367/25,27,30,31,34,35,86,87 ;181/102,105 ;73/151,152,155 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
"Ultrasonic Velocity as a Probe of Emulsions and Suspensions", by
D. J. McClements, et al., Advances in Colloid and Interface
Science, 27 (1987), Amsterdam, Netherlands, pp. 285-316. .
"Ultrasonic Velocity and Attenuation Measurements in Water-Based
Drilling Muds", by A. L. Podio et al., University of Texas at
Austin. .
"A Dynamic Computer Model of a Kicking Well", by H. V. Nickens, SPE
Drilling Engineering, Jun. 1987. .
"Delta Flow: An Accurate, Reliable System for Detecting Kicks and
Loss of Circulation During Drilling", by J. M. Speers et al., SPE
Drilling Engineering, Dec. 1987. .
"Theoretical and Experimental Development of the Ultrasonic
Diplog.SM. System", by B. B. Strozzeski, et al., SPWLA Thirtieth
Annual Logging . . . Symposium, Jun. 11-14, 1989. .
"MWD Monitoring of Gas Kicks Ensures Safer Drilling", by Robert
Desbrandes et al., Petroleum Engineer International, Jul. 1987.
.
"Instrumentation Requirements for Kick Detection in Deep Water", by
L. D. Maus, et al., Journal of Petroleum Technology, Aug.
1979..
|
Primary Examiner: Lobo; Ian J.
Attorney, Agent or Firm: Bush; Gary L. Ryberg; John J.
Claims
What is claimed is:
1. Bore hole measurement apparatus comprising,
a tool adapted for connection in a drill string in said borehole
through earth formations, said tool having a cylindrical body which
when disposed in said borehole defines an annulus between a
borehole wall and said body, said annulus having drilling fluid
with entrained drilling cuttings disposed therein, the distance
between said borehole wall and said cylindrical body defining
standoff distance,
ultra-sonic transmitter means disposed in said cylindrical body for
emitting an ultra-sonic transmitter pulse in said drilling fluid
toward said borehole wall, said ultra-sonic pulse being reflected
from said borehole wall as a borehole echo adn from said drilling
cuttings toward said cylindrical body as a cuttings echo,
ultra-sonic transducer means disposed in said cylinrical body for
generating a borehole echo signal representative of said borehole
echo and a cuttings echo signal representative of said cuttings
echo, and
logic means for distinguishing said borehole echo signal and its
time delay from said cuttings echo signal, and means for generating
a standoff signal representative of said standoff distance which is
inversely related to said borehole echo time delay, wherein said
ultra-sonic transmitter means and said ultra-sonic transducer means
includes a single transceiver in which one sensor element serves
first as a sonic transmitter and later as a sonic receiver,
wherein said transceiver is disposed in said cylindrical body so
that said sensor element faces laterally outwardly from said
cylindrical body whereby said ultra-sonic pulses and echoes travel
essentially perpendicularly between said borehole wall and said
cylindrical body in said annulus, and
wherein said logic means includes
circuit means for storing echoes where each echo is defined as the
approximate maximum amplitude and associated delay time of each
pulse received by said sensor element after said ultra-sonic
transmitted pulse has terminated.
2. The apparatus of claim 1 wherein
said drill string is rotating in said borehole, said drilling fluid
with entrained drilling cuttings disposed therein is flowing in
said annulus, and
wherein said apparatus further includes processing means for
generating said standoff signal a plurality of times each second
for a predetermined time interval and for generating from said
plurality of standoff signals an average standoff signal for said
time interval.
3. The apparatus of claim 2 further including
memory means for storing a tool diameter signal representative of a
diameter of said cylindrical body of said tool, and
processing means for generating a hole diameter signal
representative of a diameter of said borehole by adding said
diameter signal to a signal equal to twice said average standoff
signal.
4. The apparatus of claim 3 further including
clock means for generating a time signal, and
memory means for storing said diameter signal as a function of said
time signal.
5. The apparatus of claim 3 further including
communication means for transmitting said diameter signal to
surface instrumentation.
6. The apparatus of claim 1 wherein said single transceiver
includes a delay line between said sensor element and said annulus,
and wherein a delay-line echo is received by said sensor element as
a result of said ultra-sonic pulse being reflected from an
interface of said delay- line and said drilling fluid in said
annulus.
7. The apparatus of claim 1 wherein said logic means includes
delay line echo elimination logic means for eliminating stored
echoes having a delay time shorter than a predetermined delay time
after said transmitter pulse.
8. The apparatus of claim 1 wherein said logic means includes
noise rejection echo elimination logic means for eliminating stored
echoes which are noise artifacts of previous echoes rather than
reflection from said borehole or said cuttings.
9. The apparatus of claim 8 wherein said noise rejection echo
elimination logic means includes
a minimum echo amplitude function stored as a function of delay
time from said transmitter pulse,
comparison means for identifying stored echoes having amplitudes
less than said minimum echo amplitude at its associated delay time,
and
means for eliminating said identified echoes from said stored
echoes.
10. The apparatus of claim 1 wherein said logic means includes
decreasing echo amplitude logic means for eliminating a stored
echo, A.sub.M, T.sub.M, when the amplitude A.sub.M+1 of the next in
time echo, A.sub.M+1, T.sub.M+1, is larger than A.sub.M.
11. The apparatus of claim 1 wherein said logic means includes,
time separation logic means for eliminating a stored echo, A.sub.M,
T.sub.M, when the time separation T.sub.M -T.sub.M-1 between such
stored echo and a preceding stored echo, A.sub.M-1, T.sub.M-1 is
less than a predetermined minimum time T.sub.MIN.
12. The apparatus of claim 1 wherein said logic means includes,
noise rejection echo elimination logic means for eliminating stored
echoes which result from noise rather than reflection from said
borehole or said cutting, decreasing echo amplitude logic means for
eliminating a stored echo, A.sub.M, T.sub.M, when the amplitude
A.sub.M+1 of the next in time echo, A.sub.M+1, T.sub.M+1, is larger
than A.sub.M,
time separation logic means for eliminating a stored echo, A.sub.M,
T.sub.M, when the time separation T.sub.M -T.sub.M-1 between such
stored echo and a preceding stored echo, A.sub.M-1, T.sub.M-1 is
less than a predetermined minimum time T.sub.MIN,
temporary formation echo selection logic means for selecting a
final echo, A.sub.N, T.sub.N of said remaining stored echoes as a
temporary formation echo, and
double echo elimination logic means for identifying said temporary
formation echo as a double echo if said delay time T.sub.N of said
temporary formation echo is equal to approximately twice the delay
time of a previous stored echo, and it such temporary formation
echo is so identified, eliminating said final echo from said stored
echoes, whereby a penultimate echo, A.sub.N-1, T.sub.N-1, becomes
said temporary formation echo.
13. The apparatus of claim 12 wherein said logic means further
includes
echo induced sensor noise elimination logic means for comparing
said temporary formation echo A.sub.N, T.sub.N, with an immediately
preceding echo A.sub.N-1, T.sub.N-1, to identify such echo A.sub.N,
T.sub.N as a formation echo signal if A.sub.N >K*A.sub.N-1,
where K is a predetermined minimum ratio of successive amplitudes
of echoes above which an echo is unlikely to be an echo induced
noise pulse.
14. The apparatus of claim 13 further including control means for
generating and storing said formation echo signal A.sub.N, T.sub.N,
a plurality of times each second for a predetermined time interval
and for generating from said plurality of standoff signals an
average standoff signal for said time interval.
15. The apparatus of claim 14 further including
memory means for storing a diameter signal representation of a
diameter of said cylindrical body of said tool, and
processing means for generating a hole diameter signal
representative of a diameter of said borehole by adding said
diameter signal to a signal equal to twice said average standoff
signal.
16. Borehole measurement apparatus comprising,
a tool adapted for connection in a drill string in said borehole
through earth formations, said tool having a cylindrical body which
when disposed in said borehole defines an annulus between said
borehole wall and said body, said annulus having drilling fluid
with entrained drilling cuttings disposed therein,
first and second ultra-sonic transmitter means disposed
diametrically opposed from each other in said cylindrical body for
emitting first and second ultra-sonic transmitter pulses in said
drilling fluid toward said borehole wall, the distance between said
borehole wall and said cylindrical body at said first ultra-sonic
transmitter means defining a first standoff distance, the distance
between said borehole wall and said cylindrical body at said second
ultra-sonic transmitting means defining a second standoff distance,
said ultra-sonic pulses being reflected from said borehole wall as
first and second borehole echoes and from said drilling cuttings
toward said cylindrical body as first and second cutting
echoes,
first and second ultra-sonic transducer means disposed in said
cylindrical body for generating first and second borehole echo
signals representative of said first and second borehole echo
signals representative of said first and second borehole echo
amplitudes and time delays, and first and second cuttings echo
signals representative of said cuttings echoes, and
logic means for distinguishing said first borehole echo signal and
its time delay in the presence of said first cuttings echo signal
and for generating a first standoff signal representative of said
first standoff distance which is inversely proportional to said
time delay of said first borehole echo signal from said emitting of
said first ultra-sonic transmitter pulse and for distinguishing
said second borehole echo signal and its time delay in the presence
of said second cuttings echo signal and for generating a second
standoff signal representative of said second standoff distance
which is inversely proportional to said time delay of said second
borehole echo signal from said launching of said second ultra-sonic
transmitter pulse,
wherein said first and second transmitter means emit said first and
second ultra-sonic transmitter pulses alternately in time with said
logic means identifying said first borehole echo signal after said
first ultra-sonic transmitter pulse is emitted and said logic means
identifying said second borehole echo signal after said second
ultra-sonic transmitter pulse is emitted, and
processing means for generating a first standoff signal
proportional to said time delay of said first borehole echo signal
and for generating a second standoff signal proportional to said
time delay of said second borehole echo signal,
processing means for generating said first and second standoff
signals a plurality of times each second for a predetermined time
interval, and for generating from said plurality of standoff
signals an average first standoff signal and an average second
standoff signal for said time interval,
memory means for storing a diameter signal representative of a
diameter of said cylindrical body of said tool, and
processing means for generating a hole diameter signal
representative of a diameter of said borehole by adding said
diameter signal to a said average first standoff signal and to said
average second standoff signal.
17. The apparatus of claim 16 further including
clock means for generating a time signal, and memory means for
storing said diameter signal as a function of said time signal.
18. The apparatus of claim 16 further including
communication means for transmitting said diameter signal to
surface instrumentation.
19. The apparatus of claim 16 wherein said first ultra-sonic
transmitter means and said first ultra-sonic transducer means and
said second ultra-sonic transmitter means and said second
ultra-sonic transducer means are each a single transceiver in which
one sensor element serves as a sonic transmitter and as a sonic
receiver.
20. Borehole measurement apparatus for identifying large gas bubble
influxes into a borehole comprising
a tool adapted for connection in a drill string in said borehole
through each formation, said tool having a cylindrical body
defining an annulus between said borehole wall and said body, said
annulus having drilling fluid disposed therein,
ultra-sonic transceiver means disposed in said cylindrical body for
emitting an ultra-sonic pulse in said drilling fluid toward said
borehole wall and for receiving ultra-sonic echo pulses reflected
from said borehole wall, and
a phase detector for detecting the phase of said pulses and for
generating a signal indicating that an echo has high frequency
oscillations which are approximately 180.degree. out of phase from
the echo pulse, such signal indicative of the sensing of a large
gas bubble.
Description
TECHNICAL FIELD
This invention relates generally to the ultra-sonic measurement of
borehole characteristics. More particularly this invention relates
to, apparatus and methods of ultra-sonic measuring of borehole
characteristics while a well is being drilled. Still more
particularly the invention relates to measurement of borehole
diameter and gas influx of a borehole while it is being drilled.
The invention relates also to a particular ultra-sonic sensor
incorporated in the apparatus for measuring such
characteristics.
BACKGROUND OF THE INVENTION
The apparatus and methods of this invention provide for the
measurement of borehole diameter and for the detection of gas
influx while a well is being drilled.
Borehole Caliper Measurement
Knowledge of a borehole's diameter while it is being drilled is
important to the driller because remedial action may be taken by
the driller in real time, preventing the delay inherent in tripping
the drill string and conducting open-hole logging activities. If
the diameter of the borehole is over-gauge, such fact may indicate
that there is inappropriate mud flow, or an improper mud chemical
characteristic or that the well hydrostatic pressure is too low, or
that there is some other source of well-bore instability. If the
diameter of the borehole is below gauge or nominal size, such fact
may indicate that the bit is worn and should be replaced so as to
obviate the need for later well reaming activities.
Well bore diameter instability increases the risk that the drilling
string may become stuck downhole. Stuck pipe implies an expensive
and time consuming fishing job to recover the string or deviation
of the hole after the loss of the bottom of the drilling string.
Well bore diameter variation information is important to the
driller in real time so that remedial action may be taken.
Well bore diameter as a function of depth is also important
information for a driller where the borehole must be kept open for
an extended portion of time. Monitoring of well bore diameter when
the drill string is tripped out of the borehole provides
information to the driller regarding proper drilling fluid
characteristics as they relate to formation properties.
Knowledge of borehole diameter also aids the driller when deviated
holes are being drilled. When a borehole is out of gauge,
directional drilling is difficult because the drill-string,
bottom-hole assembly, and collar stabilizers do not contact the
borehole walls as predicted by the driller. Real time knowledge of
borehole diameter provides information on which to base directional
drilling decisions. Such decisions may eliminate the need for
tripping the string so as to modify the bottom-hole assembly to
correct a hole curvature deviation problem.
Real time knowledge of well bore diameter is important in logging
while drilling (LWD) operations. Certain measurements, especially
nuclear measurements of the formation, are sensitive to borehole
diameter. Knowledge of the well bore diameter under certain
circumstances can be critical for validating or correcting such
measurements.
U.S. Pat. No. 4,665,511 describes a system for measuring the
diameter of a well while it is being drilled. Such system provides
ultra-sonic transducers on diametrically opposed sides of a
drilling sub. It relies on the reception of echoes of emitted
pulses from the borehole walls, but such reception is often
confused by the presence of drill cuttings in the drilling fluid.
Measurement of the diameter of a borehole using the apparatus of
this patent may also be inaccurate where the sub is not centralized
with the axis of the borehole. Such inaccuracy may occur where the
drilling sub is adjacent the borehole wall and the diameter of the
sub is smaller than the diameter of the borehole. Under such
conditions, the "diameter" sensed by the drilling sub is in reality
a chord of the borehole which is smaller than the actual borehole
diameter.
Identification of objects of the invention with respect to borehole
caliper measurement aspects of the invention are described below
after other aspects of the invention are described.
Borehole Gas Influx Detection
Gas influx, or a "kick" into the borehole, is a serious hazard in
the drilling art since kicks, if uncontrolled, can cause well
blowouts. Well blowouts may result in loss of life, damage to
expensive drilling equipment, waste of natural resources, and
damage to the environment.
Prior art kick detection while drilling has typically involved
observation of the mud flow rate and/or mud pit volume.
Accordingly, almost every rig which uses drilling fluid or mud to
control the pressure in the borehole has some form of pit-level
indicating device that indicates a gain or loss of mud. A mud
pit-level indicating and recording device, such as a chart, is
usually located in a position so that the driller can see the chart
while drilling is occurring. When a kick occurs, the surface
pressure required to contain it largely depends upon closing
well-head BOPs quickly and retaining as much mud as possible in the
well.
Flow meters showing relative changes in return mud flow have also
been used as a kick warning device, because mud hold-up in solids
control devices, degassers, and mixing equipment affects average
pit-level. Such fluctuations in pit-level due to such factors recur
periodically during drilling and may occur simultaneously with a
kick. When such conditions are present, a return flow rate may be
the first indication of a kick.
To determine kicks as early as possible while drilling, the driller
typically uses instantaneous charts of average volume of the mud
pit, mud gained or lost from the pit, and return flow rate.
Preferably, the pit volume and return flow rate is displayed (and
possibly recorded by means of a graph) on the drilling floor so
that trends can be observed. As soon as an unexpected change in the
trends occurs, a driller checks for a kick condition.
These prior art kick detection techniques for land drilling
operations typically require ten to twenty minutes of delay from
the time a gas influx occurs at the bottom of the well until pit
volume or return mud flow rate is sufficiently affected to be
detected. For offshore operations such delay may be twice that for
land operations.
Because a kick can lead to a blowout with possible disastrous
results, prior attempts have been made to obtain information as to
gas influx into the borehole before such influx affects pit mud
volume or return flow rate. U.S. Pat. No. 4,571,603 discloses
apparatus for measuring characteristics of drilling mud with a
probe adapted for inclusion in a drill string member. Such probe
includes an ultra-sonic transducer which serves to emit sonic
pulses and receive echo signals. A gap in the path of the
ultra-sonic pulses is provided so that drilling fluid may enter the
gap. Reflections from a near surface of the gap and from a far
surface of the gap are analyzed. Such analysis is said to permit
determination of the speed of sound of the drilling fluid, sonic
attenuation, the product of fluid density and compressibility,
viscosity etc.
Such patent does not describe a practical system in a down-hole
measuring-while-drilling environment, because the probe gap may
quickly become caked or filled with mud particulate. Such caking of
the gap renders the probe inoperable for determining
characteristics of downhole drilling fluid. The apparatus and
method also ignores the presence of cuttings in the drilling fluid
which affect reflections received by an ultra-sonic transducer.
Identification of objects of the invention with respect to gas
influx or kick detection measurements of the invention are
described below.
Ultra-sonic Sensor for a Measurement While Drilling Environment
The drilling environment in which an ultra-sonic sensor must
function, if it is to measure borehole and drilling fluid
characteristics while drilling, is truly daunting. Shocks and
vibrations up to 650 G's/mSec of the drill string render prior art
ultra-sonic sensor assemblies useless. Measurement while drilling
sensors must survive for several days, unlike wireline logging
sensors, because drilling continues for such time length. Noise
created by high speed drilling fluid through drilling tools and by
tools impacting rock formations must be eliminated in signal
processing. In addition, the sensors must be capable of
withstanding pressures up to 20,000 psi and temperatures up to
150.degree. C. as well as mechanical abrasion and direct hits on
the sensor face.
Identification of objects of the invention with respect to the
ultra-sonic sensor aspects of the invention are described
below.
IDENTIFICATION OF OBJECTS OF THE INVENTION
Borehole Caliper Measurement
It is a primary object of the invention to measure-while-drilling
the borehole diameter and tool standoff by pulse-echo techniques by
recognizing and eliminating reflections from cuttings in the
drilling fluid returning to the surface between the tool and the
borehole wall.
It is another object of the invention to measure-while-drilling
borehole diameter and tool standoff by pulse echo techniques and to
statistically process such measurements downhole to significantly
improve the accuracy of such measurements.
It is still another object of the invention to mount a pulse echo
sensor on or near a stabilizer of a drilling tool to minimize
inaccuracies caused by such tool not being centralized with the
axis of the borehole.
It is still another object of the invention to measure while
drilling borehole diameter and tool standoff by pulse echo
techniques and to transmit a signal representative of same to the
surface.
Borehole Gas Influx Detection
Another primary object of the invention is to provide a practical
and reliable method and apparatus for measuring gas influx into a
well while it is being drilling and telemetering a signal
representative of that measurement to the surface.
Another object of the invention is to provide a method and
apparatus for detecting gas influx into a borehole even though
drill cuttings are entrained within the borehole fluid.
Another object of the invention is to provide a method and tool for
assessing gas influx into a borehole by pulse-echo measurement of
flowing drilling fluid as it returns to the surface in the annulus
between the tool and the borehole.
Another object of the invention is to provide alternative
techniques for assessing gas influx into a borehole and using such
techniques as redundant indicators of gas influx.
Another object of the invention is to provide apparatus and method
for measuring the sonic impedance of drilling fluid in a borehole
by assessing echoes from the interface between a delay line and
such drilling fluid.
Another object of the invention is to provide apparatus and method
for measuring sonic attenuation of drilling fluid in the borehole
by assessing echoes from the borehole wall.
Another object of the invention is to provide apparatus and method
for detection of large bubbles in the borehole drilling fluid.
Ultra-sonic Sensor for a Measuring-while-drilling Environment
Another primary object of the invention is to provide an
ultra-sonic sensor and associated electronics and tool in which it
is placed which can survive extremely harsh forces, temperatures,
pressures and noise present in a borehole while it is being
drilled.
Another object of the invention is to provide a tool structure and
ultra-sonic sensor which are not subject to mud caking while
measuring characteristics of drilling fluid as it flows past the
sensor.
Another object of the invention is to provide a sensor assembly
which includes a delay line including a structure for focusing
ultra-sonic pulses toward the borehole.
Another object of the invention is to provide a sensor assembly
which creates a smooth outside profile with a downhole drilling
tool to prevent caking of drilling fluid particulate in the path of
ultra-sonic pulses and echoes.
Another object of the invention is to provide a mounting structure
for a pulse echo sensor assembly in a downhole drilling tool to
protect the assembly from extremely high shock forces.
Another object of the invention is to provide a pulse echo sensor
assembly to accommodate thermal expansion of components due to
extremely high downhole temperatures.
Another object of the invention is to provide a pulse echo sensor
assembly which prevents fluid invasion into sensor components even
under extremely high pressures of a borehole environment.
Another object of the invention is to provide mechanical noise
rejection structures to reduce noise generated by high velocity mud
flow through the drilling tool, thereby allowing a large range of
signal detection after attenuation.
Still another object of the invention is to provide electronic
control and processing circuits for emitting and receiving
ultra-sonic pulses and echoes and for processing echo data to
generate caliper and gas influx signals.
SUMMARY OF THE INVENTION
The objects identified above, as well as other advantages and
features of the invention, are preferably incorporated in an
ultra-sonic system disposed within a measuring-while-drilling (MWD)
or logging-while-drilling (LWD) apparatus to perform hole caliper
monitoring and/or gas influx detection.
The system includes an ultra-sonic transceiver installed in a drill
collar. Such drill collar functions in the drilling process to put
weight on the bit, etc. In other words, it functions as an ordinary
drill collar independent of the MWD measuring apparatus described
here. A second identical transceiver is preferably installed at the
azimuthal opposed position of the first transceiver in the same
collar, and at the same axial position. This second transceiver
improves the reliability of gas detection and the caliper
accuracy.
The transceiver is designed to generate an ultrasonic pulse in the
mud in the direction perpendicular to the face of the collar. The
wave pulse travels through the mud, reflects from the formation
surface and comes back to the same transceiver which, after the
ultra-sonic pulse has been emitted, acts as a receiver. The travel
time of the pulse in the mud is proportional to the standoff
distance of the tool from the borehole wall.
The transceiver includes a solid "delay-line" between a ceramic
sensor and the drilling fluid. Such "delay-line" reflects a portion
of the emitted sonic pulse back to the sensor from the interface of
the delay line and the mud. The amplitude of such pulse is related
to the sonic impedance of the mud. Such sonic impedance depends
directly on the amount of gas in the mud, i.e., it depends on the
density of the mud. Accordingly, the sonic impedance of the mud is
an important parameter for down-hole gas influx detection.
Providing a delay-line in front of the sonic sensor advantageously
allows echo detection where the tool is close to the borehole.
Furthermore, such delay-line provides focusing, protection of the
sensor, and other mechanical functions as described below.
In addition to the transceiver, the drill string collar includes
electronic circuits, a microprocessor, and memory circuits to
control the sensor and to receive echo signals and process them.
Processed signals may be stored in down-hole memory (caliper for
example), or may be transmitted to the surface by a standard
measuring-while-drilling mud pulse device and method. Both methods
(storage and transmission) can be used simultaneously.
Alternatively, the caliper signals may be stored and the gas influx
signals transmitted to the surface in real time.
Borehole Caliper Measurement
The apparatus of the invention provides a tool standoff measurement
to determine the hole diameter when the tool is rotating (which is
the normal case during drilling), or when the tool is stationary.
When the tool is rotating, the transceiver sends the sonic pulse
through the mud gap distance between the tool and borehole wall.
Such gap varies with the tool rotation. The measured standoffs are
accumulated for statistical processing, and the average hole
diameter is calculated after several turns. Several standoff
measurements are preferably evaluated each second. Because the
typical drill string rotation speed is between about 50 to 200 RPM,
an average accumulation time from about 10 to about 60 seconds
creates enough data for accurate averaging.
Providing a second transceiver diametrically opposed from the first
improves the diameter measurement when the tool axis moves from
side to side in the well-bore during drilling. One transceiver
measures the standoff on its side. Then immediately thereafter the
other transceiver measures the standoff on the other side of the
tool. An instantaneous firing of both transceivers is not required
as long as tool movement in the time between the two transceiver
measurements is small.
The hole diameter is determined by adding the tool diameter to the
standoffs measured on successive firings. A number of borehole
diameter determinations are accumulated and averaged to produce a
borehole measurement. Additional processing according to the
invention relates to processing for rejection of false echoes. Such
processing identifies formation echoes which occur after echoes
from drilling cuttings in the drilling fluid. The processing also
distinguishes formation echoes from its multiple arrivals, and from
sensor noise.
An important feature of a particularly preferred embodiment of the
present invention is to mount the transceiver near a stabilizer or
on the stabilizer blades of the collar. Such placement of the
transceiver improves the accuracy of the caliper measurement.
Borehole Gas Influx Detection
Gas influx or a "kick" is detected by two techniques which may be
used individually or together to confirm each other. The first
technique is to measure the sonic impedance of the mud in the
borehole while the borehole is being drilled. The other technique
is to measure the attenuation of the mud in the borehole while it
is being drilled.
To measure mud impedance, the transceiver includes a delay-line in
front of the sensor. When a sonic pulse is emitted from the sensor,
it reaches the front face of the delay-line. Part of the sound
pulse is transmitted into the drilling fluid. The other part is
reflected back toward the sensor. Because the reflection
coefficient depends on the mud impedance, the amplitude measurement
of the reflected signal is representative of mud impedance as a
function of time. The occurrence of a gas influx can be determined
by monitoring variations in the measured mud impedance versus time,
or alternatively by comparing the measured mud impedence to a
reference measurement of the impedance of "clean" mud.
Mud attenuation is defined as the signal amplitude reduction with
an increased standoff. Measurement of mud attenuation requires
several measurements of the amplitude of the sonic echo signal
after it has travelled different standoff distances in the mud.
Such echo for this invention is the borehole echo which returns to
the sensor after reflection from the borehole wall. It is important
that the emitted pulse amplitude and frequency be maintained
substantially constant for all the several measurements of the
attenuation. For a predetermined measurement period, several
standoff values are measured as the tool is moving in the
well-bore. For each standoff, the amplitude of the formation echo
is measured. Then, the logarithm values of this amplitude versus
the standoffs are stored in a table. The slope of a line fit to the
logarithm amplitude values is determined.
A major advantage of the method and apparatus of the invention over
other methods to monitor mud attenuation is the performance of the
measurement through a mud sample which is part of the drilling
fluid flow of the annulus between borehole wall and the drilling
tool. Accordingly, there is no risk of plugging a "gap" measurement
with cuttings, drilling debris, or sticky clay, because the mud
flow and the tool movement through the mud clean the sensor
face.
Ultra-sonic Sensor for a Measurement While Drilling Environment
The ultra-sonic sensor assembly of the invention is adapted for
placement in the wall or stabilizer fin of a drilling collar which
is placed above the drilling bit of a down-hole drilling assembly.
The ultra-sonic sensor assembly includes a sensor stack having an
inner sound absorbing backing element, a piezo-electric ceramic
disk stacked outwardly adjacent the backing element, and a
delay-line. Such delay-line is fabricated of rigid plastic material
and is disposed outwardly of the ceramic disk. Such delay-line
includes an outwardly facing depression for focusing an ultra-sonic
pulse into the drilling mud toward the borehole wall. An elastomer
or epoxy fills the depression to present a smooth face to the
flowing mud and the borehole wall.
The sensor assembly includes electrodes attached to the outer and
inner surfaces of the ceramic disk and connector pins for
connecting the assembly to an electronics module disposed within
the drilling collar. Such electronics module includes control and
processing circuitry and stored logic for emitting ultra-sonic
pulses via the ceramic disk sensor and for generating echo signals
representative of echoes of such pulses which return to the disk
sensor. Such electronic module also preferably includes a source of
electrical energy (such as a battery or source of d.c. current from
a MWD tool) and downhole memory for storing signals as a function
of time. It interfaces with an MWD telemetry module for
transmitting measurement information to the surface while drilling
in real time.
The backing element of the ultra-sonic sensor assembly is
characterized by a solid portion (preferably, but not necessarily
cylindrical in shape) disposed inwardly adjacent to the ceramic
disk and a frusto-conical portion disposed inwardly adjacent the
solid cylindrical portion.
The sensor stack includes a rubber jacket disposed around the
backing material, the ceramic disk, and a matching layer disposed
outwardly adjacent the ceramic disk. A tube of elastomeric material
is placed between the rubber jacket and a metallic cup in which the
sensor stack is placed. The delay-line is spring mounted in the cup
outwardly of the rubber jacket and elastomeric tube which surround
the sensor stack.
Two sources of noise are present in the vicinity of the sensor
stack of the tool. The first can be characterized as drilling noise
which is of a lower frequency band than that of the acoustic
pulse-echo apparatus of the sensor. The second is pumping noise
which is characterized by a frequency band which extends into the
frequency range of the pulse-echo apparatus.
Pumping noise is mechanically filtered not only by the rubber
jacket surrounding the sensor stack, but also by a filter ring
mounted radially outwardly of the ceramic disk about the rubber
jacket. The backing element is shock protected by rubber packing
between it and the elastomeric sleeve which envelops the stack.
Drilling noise, which may be of extremely high amplitude, is
partially mechanically filtered by the rubber jacket and filter
ring described above and partially electronically filtered.
Electronic filtering is achieved by an electronic high-pass filter
placed prior to signal amplification to avoid amplifier saturation
which could mask ultra-sonic signal detection during amplifier
saturation and recovery time.
BRIEF DESCRIPTION OF THE DRAWINGS
The objects, advantages and features of the invention will become
more apparent by reference to the drawings which are appended
hereto and wherein like numerals indicate like parts and wherein an
illustrative embodiment of the invention is shown, of which:
FIG. 1 illustrates an ultra-sonic measurement tool placed in a
drill string of a rotary drilling system, where the tool measures
borehole diameter and fluid influx while the drill string is
turning or stationary;
FIG. 1A illustrates an alternative placement of an ultra-sonic
sensor assembly in the wall of a drill collar, rather than in
stabilizing fins of such drill collar;
FIG. 2A illustrates in schematic form the ultra-sonic sensor
assembly of the invention, and FIG. 2B illustrates a preferred
embodiment of the sensor assembly of the invention;
FIG. 3A illustrates in block diagram form the circuits, computer
and stored program of a tool electronics module which controls the
firing of a source pulse transmitter and the echo signal reception
of one or more sensors and which processes echo data to generate
signals representative of borehole diameter, mud impedance and mud
attenuation, and FIG. 3B illustrates a stored program
implementation of a firing/threshold/counter apparatus and method
to digitize filtered echo signals;
FIG. 4 is a schematic diagram illustrating ultra-sonic pulse
generation by the ceramic disk of the sensor stack and the echoes
from the interface of the delay-line with the drilling fluid and
the echoes from the formation or borehole wall;
FIG. 5 is a voltage versus time illustration of the ultra-sonic
pulse emitted into the drilling fluid toward the borehole wall and
various return echo pulses from the interface of the delay-line and
the drilling fluid and from the borehole wall;
FIGS. 6A and 6B illustrate schematically and by a voltage versus
time graph of the relative amplitude and time spacing of an emitted
ultra-sonic pulse and its return echo, first from the interface
between the delay-line of the sensor stack and drilling fluid of
the borehole, and second from the borehole wall;
FIGS. 7A and 7B illustrate schematically, and by a voltage versus
time graph, the relative amplitude and time spacing of an emitted
ultra-sonic pulse and return echoes from the delay-line-drilling
fluid interface, from the borehole wall, and from cuttings in the
drilling fluid;
FIGS. 8A and 8B are illustrations similar to those of FIGS. 5A, 5B
and 6A, 6B illustrating small gas concentration in the drilling
fluid resulting in a drilling fluid sonic attenuation increase
which reduces borehole echo amplitude;
FIGS. 9A and 9B are illustrations similar to those of FIGS. 7A and
7B but for the case of high concentration of small gas bubbles in
the drilling fluid, resulting in almost complete attenuation of the
borehole echo, but also resulting in an increase in the amplitude
of the delay-line/drilling fluid echo due to a change in the sonic
impedance;
FIGS. 9C and 9D are illustrations similar to those of FIGS. 9A and
9B but for the case of large gas bubbles in the drilling fluid,
resulting in a large amplitude echo which is sensed after the
delay-line/drilling fluid echo;
FIG. 10 illustrates echoes which are sensed due to drilling
cuttings entrained in the drilling fluid;
FIG. 11 illustrates that echoes may be received which are multiple
reflections from the borehole;
FIG. 12 illustrates late arriving noise spikes which result from
true formation echoes;
FIG. 13 is a flow diagram illustrative of logic steps performed by
a computer in the electronics module of the tool to identify
borehole echoes and delay-line echoes under the conditions
illustrated in FIGS. 6A, 6B to 12;
FIG. 14 illustrates graphically the determination of mud
attenuation by plotting the log amplitude of borehole echoes as a
function of tool standoff; and
FIG. 15 illustrates the variables of mud impedance and mud
attenuation in decibels plotted as a function of drilling time,
with a specific illustration of the effect on such variables of gas
influx into the borehole at a particular time.
DESCRIPTION OF THE INVENTION
Introduction
FIG. 1 illustrates a rotary drilling rig system 5 having apparatus
for detection, while drilling, of borehole diameter and for gas
influx into the borehole. Downhole measurements are conducted by
instruments disposed in drill collar 20. Such measurements may be
stored in memory apparatus of the downhole instruments, or may be
telemetered to the surface via conventional
measuring-while-drilling telemetering apparatus and techniques. For
that purpose, an MWD tool sub, schematically illustrated as tool
29, receives signals from instruments of collar 20, and telemeters
them via the mud path of drill string 6 and ultimately to surface
instrumentation 7 via a pressure sensor 14 in stand pipe 15.
Drilling rig 5 includes a motor 2 which turns a kelly 3 by means of
a rotary table 4. A drill string 6 includes sections of drill pipe
connected end-to-end to the kelly and turned thereby. A plurality
of drill collars such as collars 26 and 28 and collar 20 of this
invention, as well as one or more MWD tools 29 are attached to the
drilling string 6. Such collars and tool form a bottom hole
drilling assembly between the drill string 6 of drill pipe and the
drilling bit 30.
As the drill string 6 and the bottom hole assembly turn, the drill
bit 30 bores the borehole 9. An annulus 10 is defined between the
outside of the drill string 6 and bottom hole assembly and the
borehole 9 through earth formations 32.
Drilling fluid or "mud" is forced by pump 11 from mud pit 13 via
stand pipe 15 and revolving injector head 17 through the hollow
center of kelly 3 and drill string 6 to the bit 30. Such mud acts
to lubricate drill bit 30 and to carry borehole cuttings or chips
upwardly to the surface via annulus 10. The mud is returned to mud
pit 13 where it is separated from borehole cuttings and the like,
degassed, and returned for application again to the drill
string.
The tool 20 of the invention includes at least one ultra-sonic
transceiver 45, but preferable also a second transceiver 46 placed
diametrically opposed from the first, for measuring characteristics
of the borehole while it is being drilled.
Such measurements are preferably conducted while the borehole is
being drilled, but they may be made with the drill string and the
bottom hole assembly in the borehole while the bit, bottom hole
assembly and drill string are not turning. Such measurements may
even be conducted while the entire string, bottom hole assembly and
bit are being tripped to and from the bottom of the borehole, but
the primary use of the measurement is while the borehole is being
drilled. As mentioned above, such characteristics of the borehole 9
may be telemetered to the surface via MWD telemetering tool 29 and
the internal mud passage of drill string 6, or they may be recorded
and stored downhole and read out at the surface after the drill
string has been removed from the borehole as will be explained
below.
The transceivers 45, 46 are preferably mounted on stabilizer fins
27 of collar 20 or may be mounted in the cylindrical wall 23 of the
collar 20' as illustrated in FIG. 1A. Although it is preferred that
transceivers 45, 46 be mounted on a collar which is stabilized,
such transceivers 45, 46 may of course be mounted on a cylindrical
collar which does not have stabilizing fins.
Electronic circuits and microprocessors, memories, etc. used to
control transceivers 45, 46, receive data from them, and process
and store such data are mounted on a sleeve 21 which is secured
within collar 20 or 20'. Such sleeve has a path 40' by which
drilling mud may pass through the interior of drill string 6 to the
interior of bit 30.
The tools (collars) 20 or 20' including transceivers 45 and 46 and
the electrical apparatus mounted on sleeve 21 are especially
adapted to measure borehole diameter and to measure characteristics
of the mud which returns upwardly in annulus 10 after it passes
through bit 30. Such mud usually has entrained cuttings, rock chips
and the like and may have gas bubbles 19 entering the annulus mud
from an earth formation. It is the fact of the occurrence of this
gas influx or "kick" and the time that it occurs as the borehole is
being drilled that is important to the driller. As explained below,
the apparatus and methods of this invention measure characteristics
of the returning mud, such as sonic impedance and sonic
attenuation, to determine if and when a gas influx has
occurred.
Description of Ultra-sonic Transceivers and Placement on Collar
1) Ultra-sonic sensor construction in general
FIGS. 1, 1A and 2A illustrate schematically the ultra-sonic
transceivers 45, 46 of the invention. Such transceivers are secured
in the collar 20 or 20' to face the annulus 10 of the borehole 9.
FIG. 2A shows that the transceiver is disposed in a steel cup 51
secured within a cavity of the cylindrical wall 23 of collar 20' or
stabilizer fin 27 of collar 20. Alternatively, the transceiver
could be installed directly into a cavity of the collar 20.
The sensor of the transceiver 45 is a piezo-electric disk 54 which
is preferably a flat circular slice of ceramic material. Disk 54 is
mounted between one (or more) impedance matching layer 56 and a
suitable absorbing or backing element 58. The matching layer 56 is
fabricated of a low density material such as magnesium or hard
plastic. The backing element 58 includes high impedance grains
(typically tungsten or lead balls) molded in low impedance material
(such as epoxy or rubber).
These three elements, the ceramic disk 54, matching layer 56 and
backing element 54 are hereinafter referred to as the sensor stack.
They cooperate to generate or emit an ultra-sonic pulse outwardly
toward the wall of borehole 9 through drilling mud of annulus 10
and to receive sonic echo pulses which are reflected back to
ceramic disk or sensor 54.
The sensor stack is encapsulated in a rubber jacket 60 which
isolates the sensor stack from high pressure drilling fluid in
annulus 10. Such fluid isolation avoids electrical shorting and
corrosion of the sensor stack elements and provides electrical
insulation of electrodes, leads, and connections to sensor disk
54.
The space 62 between the jacket 60, backing material 58, and cup 51
is filled with a highly deformable material such as rubber. Such
rubber and the rubber jacket 60 cooperate to surround the sensor
stack with rubber in order to dampen noise transmitted in the
collar 20 from the drilling process, and partially to absorb high
shock forces on the sensor stack created during a typical downhole
drilling operation. The rubber in space 62 also functions to allow
the sensor stack to move or deform under pressure or due to thermal
expansion.
Electrical leads 64 are connected between outer and inner surfaces
of sensor 54 and terminals 66 of electronics module 22. Such leads
64 run through the rubber 62 and through the cup 51 as will be
explained in greater detail below.
Additional noise filtering is preferably provided by a ring 68 of
low impedance material placed about the rubber jacket 60 in
longitudinal alignment with sensor disk 54. Ring 68, which is made
of materials such as epoxy, rubber, plastic and the like, (or even
grease or mud) reduces the level of high frequency noise
transmitted through the steel collar 20 that reaches the disk 54 .
Ring 68 reflects noise transmitted through the drill string and
collar which could reach ceramic disk 54. It acts as a mechanical
high frequency noise insulator or filter so as to increase the
signal to noise performance of the transceiver 45. A high signal to
noise ratio is important under drilling conditions where high speed
mud flowing in path 40' of the collar 20 might generate noise in
the frequency range of the transceiver measurement.
A delay-line 70 is placed outwardly of sensor disk 54. Such
delay-line 70 provides mechanical protection to the sensor stack as
well as providing an important role in the measurement of drilling
fluid sonic impedance. Measurement of drilling fluid sonic
impedance provides one means for gas influx detection. The
delay-line 70 also facilitates short stand off detection of the
borehole as explained below.
The delay-line 70 is fabricated of low sonic impedance materials
such as plastic, epoxy or rubber. It distributes impact forces on
its outer face over a relatively wide area inwardly toward the
matching layer 56. The delay-line 70, rubber jacket 60 and matching
layer 56 cooperate to broadly distribute such impact forces to the
ceramic disk 54, which is fabricated of an inherently brittle
material. Furthermore, delay line 70 is mounted with respect to cup
51 so as to isolate the sensor stack from further torque caused by
the outer face of the delay-line 70 and collar 20 rubbing against
the borehole when the drill string is turning in the borehole 9.
The delay-line also protects the rubber jacket 60 from damage due
to banging and scraping of the tool 20 against the wall of borehole
9.
The delay-line 70 is spring mounted within cup 51 by springs 72
which maintain contact between delay-line 70 and rubber jacket 60
even if the sensor stack moves outwardly or inwardly due to
expansion or contraction with temperature and pressure
variations.
In summary, FIG. 2A illustrates that the ceramic sensor 54 is
protected both acoustically and structurally. Structural protection
of sensor disk 54 is provided by its shock mounting: longitudinally
by the steel cup 51 and the tightly fitting rubber jacket 60;
inwardly by the soft rubber filling 62; and outwardly by the
delay-line 70 and its spring 72 mounting with respect to cup 51.
Such spring mounting allows expansion and compression of the
backing element 58 under pressure and temperature changes toward
the outward face of transceiver 45. Rubber sleeve 60 serves to
isolate the sensor stack from pressurized fluid and to allow its
outer face to move inwardly and outwardly, while maintaining
contact with delay-line 70.
2) Ultra-sonic sensor preferred construction
FIG. 2B illustrates a preferred construction of the transceiver
sensor assembly 45 of the invention. The sensor stack comprising
ceramic disk 54, matching layer 56 and backing element 58 are
mounted within metallic cup 51.
The ceramic disk 54 is fabricated of material characterized by low
sonic impedance and high internal damping. Lead metamobate ceramic
polarized over its entire surface is preferred. When an electrical
voltage is applied across its outer and inner flat surfaces, the
thickness of the ceramic disk changes slightly. When the impressed
voltage is removed, the ceramic disk returns to its original
thickness. If the ceramic disk has an oscillating voltage of a
certain time length, here called a pulse, the ceramic disk
oscillates. An acoustic pulse is emitted from the disk because of
the oscillating thickness of the ceramic disk changes in response
to the oscillating voltage.
With no voltage impressed on the disk, it serves as a receiver.
When an acoustic wave or oscillating pulse is applied to the face
of the disk, an electrical oscillating signal between the two faces
of the disk is generated.
In a pulse-echo sensor or transceiver, i.e., the ceramic disk 54 of
the transceiver 45 of this invention, the same ceramic disk is used
to emit an acoustic pulse and receive an echo of the emitted pulse
and produce an electrical signal in response thereto.
The oscillations of the ceramic disk 54 during the emitting phase
are preferably damped before the disk is used to receive a
returning echo acoustic wave. Such damping must be effective
because the returning echo pulses are relatively small in
amplitude. In other words, sensor ringing noise after the emitting
phase should be kept to a minimum.
Decay control of the emitting oscillation is a primary function of
backing element 58. It should be in contact with ceramic disk 54 as
shown in FIG. 2B. Backing element 58 drains the acoustic energy out
of the ceramic disk 54 after an emitting voltage pulse is applied
thereto. Backing element 58 absorbs and dissipates such energy so
that it will not bounce backwards toward the ceramic disk 54 to
generate a noise signal after the emitting phase is over.
Specifically, the backing element 58 preferably has a sonic
impedance approximately the same as the material of the ceramic
disk 54. Accordingly, little acoustic energy is reflected back
toward the ceramic disk 54 as it meets the interface between
ceramic disk 54 and backing element 58. On the other hand, the
backing element 58 should have high sonic attenuation so that
energy into the backing is quickly attenuated as it travels
backward into the backing element and bounces from its extremities.
It is important that the backing element be fabricated of a
material which maintains its properties of high acoustic
attenuation and ceramic matching . impedance under conditions of
high pressure and high temperature.
The preferred raw material for backing element 58 includes
unvulcanized rubber stock, rubber compounding chemicals and
vulcanizing agents, and tungsten powder. A roll mill is used to mix
the compounding chemicals and vulcanizing agents into the rubber
stock, and for the subsequent mixing of tungsten powder into the
compounded stock. Once the tungsten and rubber have been thoroughly
blended, the resulting material is removed from the mill and
compression molded in a heated platen press to form and vulcanize
the finished composite.
The preferred rubber stocks are synthetic isobutylene-isoprene
elastomers. The tungsten powder should be of small grain size. The
compounding chemicals and vulcanizing agents include small amounts
of ZnO powder, Stearic Acid and Resin SP. The elastomer, tungsten
powder, compounding chemicals and vulcanizing agents may be
selected in proportion and grain size and mixed and processed
according to well known techniques of powder metallurgy to form a
backing element with the properties identified above.
The matching layer 56 is preferably fabricated of a thin layer of
30% carbon-filled PEEK. PEEK is a hard plastic having a chemical
name polyetheretherketone. The optimum impedance of matching layer
56 is selected such that it is substantially equal to the square
root of the impedance of the ceramic disk 54 multiplied by the
impedance of rubber layer 60.
Virgin PEEK hard plastic is preferred as the material for
delay-line 70. Epoxy or phenolic may be substitute materials for
delay-line 70. The sonic impedance of PEEK provides excellent sonic
coupling with heavy drilling mud. Its sonic attenuation is low and
has good mechanical and chemical properties for downhole
application.
A concave outwardly facing depression 71 of the outer face of
delay-line 70 is preferably provided in transceiver 45. Such
depression 71 provides a small amount of focalization of the sonic
energy emitted and received via the delay line 70. Such
focalization improves the reflection of borehole echoes where
rugose walls are encountered.
Such depression 71 also provides separation between the outer face
of the transceiver 45 and the borehole wall when the collar 20 is
not separated from the borehole wall. With such "zero stand-off"
condition, returning echoes from the outer face of the delay line
70 may be separated from zero stand-off formation (borehole wall)
echoes.
The depth of the depression 71 in the outer face of delay-line 70
is preferably small so as to avoid the possibility that mud cake of
drilling cuttings, sticking shales, and mud particulates do not
accumulate there. Excessive concentration of mud cake in the path
of the sonic pulse excessively attenuates a returning borehole
echo.
An isolation jacket 59 isolates the sensor stack elements 58, 54
and 56 from water entry via the steel cup 51. The isolation jacket
59 includes a steel sleeve inner part 61 and a rubber jacket outer
part 60. The outer part 60, preferably of viton type rubber, is
molded onto the steel sleeve 61. A groove 80 in the inner steel
sleeve 61 has an O-ring 81 placed in it which provides borehole
fluid isolation via the cup 51 to the sensor stack.
Fluid isolation is also provided by means of the viton jacket outer
part 60, but drilling fluid pressure is applied about the jacket 60
which separates the sensor stack from the drilling mud. Thus,
although isolated from fluid, the sensor stack is under the same
pressure as the drilling mud.
An electrical feed-through element 84 is provided in an inner hole
86 of the cup 51. A flange 88 of feed-through element 84 is
disposed between shoulder 90 of cup 51 and a bottom annular end 92
of steel sleeve inner part 61 of the isolation jacket. Groove 94 of
feed-through element 84 has an O-ring 96 placed in it to provide
back-up fluid isolation of the electronic modules 22 from inside
the cup 51. Electrical pins 64 run from an inner position of cup 51
through feed through 84 and terminate at feet 98.
A thin aluminum sheet 104 is secured in contact with the outer face
of ceramic disk 54 by means of an epoxy glue. A strip of aluminum
106 extends from the sheet 104 inwardly to a terminal point 108
inwardly of the frusto-conical surface of the backing element 58. A
conductive wire 112 is attached between one of the feet 98 of the
electrical pins 64 and the terminal point 108. A conductive wire
110 is secured between the other of the feet 98 of the electrical
pins 64 and a sheet of brass 114 which covers almost the entire
conical surface of backing element 58.
The brass electrode 114 includes several folds and kinks (not
illustrated) to allow thermal expansion of the backing. It is
secured to the backing element 58 by means of an epoxy glue. Such
glue is non-conductive, but enough contact is provided such that
electrical contact is made between the brass sheet and the tungsten
grains of the backing material to establish electrical conductivity
between wire 110, brass sheet electrode 114, backing material 58,
and the inner face of ceramic disk 54.
Connection to the backing element 58 by means of sheet electrode
114 is advantageous because it avoids providing a third electrode
between the inner face of the ceramic disk 54 and backing element
58 which could decrease the damping function of the backing. Also
the wire 110 is not subjected to extreme thermal expansion because
it is connected near the inner tip of the conical portion of
backing element 58.
The space between the interior of isolation jacket 59, backing
element 58, and feed through element 84 is filled outwardly with
RTV silicon rubber 100 and inwardly with epoxy 102. The RTV rubber
100 allows the wire 112, which runs from a foot 98 of pins 64 to
terminal 108 of aluminum 106, to move outwardly or inwardly with
movement of sensor stack 58, 54, 56. Wire 112 is looped within
rubber 100 allowing it to move radially with radial movement of the
sensor stack. In order to limit large thermal expansion however,
the volume of RTV rubber 100 filling is limited because of the
large thermal expansion of RTV rubber at high temperature.
Accordingly, the inner space is filled with epoxy 102.
Filling such inner space 102 with epoxy is advantageous because the
thermal expansion of epoxy is smaller than that of RTV rubber. The
epoxy 102 also serves to centralize and secure the tip of the
conical section of backing element 58 and to prevent the ceramic
disk 54 from being displaced inwardly in cup 51 with multiple heat
or pressure cycles. Such epoxy 102 also serves to close the inner
side of the sensor stack via spaces from inside the transceiver
45.
A thin tube 116 of nitrile rubber is placed about the cylindrical
sides of the rubber jacket outer part 60. Such tube provides a
sliding surface of contact for rubber jacket outer part 60 when
such rubber jacket moves outwardly or inwardly with changes of
temperature. The tube 116 also limits inward displacement of
delay-line 70 if a shock force is applied to the outer face of
delay-line 70. Accordingly, the tube 116 provides limited shock
absorbing protection of ceramic disk. 54 when the transceiver 45 is
in service while drilling a borehole.
A ring 118 is placed about jacket 60 and tube 116 in the vicinity
of ceramic disk 54. It is constructed of low sonic impedance
material in order to improve acoustic reflection and thus isolation
of the disk 54 against drilling and pumping or high speed fluid
flow noise transmitted through steel drilling pipe 6, collar 20 and
bit 30. Holes 120 in filler ring 118 provide a space to relieve
pressure in the annulus between tube 116 and cup 51.
Wave springs 72 act between flanges 122 of delay-line 70 and
shoulder 123 of window nut 125 to force delay-line 70 inwardly
against the outer annular edge of tube 116 and the outer surface of
jacket 62. Window nut 125 is secured within cup 51 by threads 126.
Thus, the springs 72 serve not only to force window 70 properly
adjacent jacket 62, matching layer 56 and ceramic disk 54, it also
serves to protect ceramic disk 54 from shock impacts against the
outer face of delay-line 70. Such shock impacts are also partially
absorbed by the tube 116, jacket 62, backing element 58 and RTV
rubber filler 100.
Pins 124 placed in mating holes of cup 51 and delay-line 70 prevent
rotation of delay-line 70 with respect to the sensor stack.
Accordingly, friction forces on delay-line 70 from contact with
borehole wall 9 during tool rotation are not transferred to the
sensor stack.
The cup 51 includes two holes 128, 130 which are perpendicular to
the axis of the sensor 45. When a pin is inserted in hole 128, for
example, the window nut 125 is locked in rotation. When a pin is
inserted in hole 130, cup 51 is looked in rotation, which allows
window nut 125 to be removed when needed. O-ring grooves 132, 134
in which O-rings are placed when cup 51 is placed in a cavity of
collar 20 provides isolation of the interior of collar 20 from
drilling fluid in the annulus 10.
In order to improve the accuracy of the caliper or borehole
diameter measurement, and to broaden the hole size range detectable
with the transceiver 45 of this invention, the transceiver 45 of
FIGS. 2A and 2B is preferably mounted near or on the stabilizer
blades 27 of the collar 20 as illustrated in FIGS. 1 and 1A. The
accuracy of the ultra-sonic measurement is enhanced for several
reasons.
First, where the transceiver is mounted on a stabilizer fin, there
is less mud through which an emitted pulse must travel from the
sensor to the borehole wall and back. Second, there is less
eccentricity or canting of the tool 20 in the borehole 9 in the
vicinity of the stabilizer blades, so that the standoff distance s
measured by two diametrically opposed transceivers result in a
better measure of a diameter of the borehole. Ideally borehole
diameter should be measured perpendicularly to the borehole
walls.
Third, with a shorter distance between the sensor and borehole
wall, there is less spreading of the sonic beam resulting in
greater signal reflection back to the transceiver from the borehole
wall. Fourth, with shorter standoff distances, especially where
transceivers 45, 46 are mounted on stabilizer blades, higher sonic
frequencies may be used thereby improving the accuracy of detection
of the first borehole echo. Finally, but importantly, the
measurement of the diameter of the borehole should be accomplished
with the tool centered in the borehole so that the actual diameter
of the borehole is measured rather than a chord of such borehole.
Providing the transceiver on a stabilizer fin of a collar or on a
collar having stabilizer fins centers the collar in the borehole
and as a result, the standoff measurement with the transceiver and
associated electronic is more accurate.
3) Electronic Module
The electronic module 22 of collar 20 is illustrated in FIG. 3A.
Such module is connected to terminals 66 which are connected to
sensors 45 and 46 mounted on collar 20 as discussed above. A
downhole battery 150 is preferably provided in module 22 as a d.c.
power source. Other sources of electrical power are of course known
in the art of downhole tool design. High voltage supply 152 steps
up the d.c. voltage to power pulser 154 which generates a high
frequency oscillation at a preferred frequency of about 670 KHz.
Computer 160 and pulser 154 direct short bursts of these high
frequency voltage oscillations first to leads 156 for application
to sensor 45, and after a receive time for sensor 45 has passed,
then to leads 158 for application to sensor 46. Of course, one
sensor only may be used, or more than two, but two diametrically
opposed sensors are preferred for the measurements described
below.
The received voltage pulses, or return echoes, are sensed on leads
64 of sensor 45 and 46 following each burst of sonic pulses. Such
voltages are applied via lead pairs 162, 164 to multiplexer 166.
Multiplexer 166 in turn, under control from computer 160, passes
the return echo voltages first to high pass filter 168 where low
frequencies in the return voltage pulses are removed.
A variable gain amplifier 170 amplifies the return signal which is
then filtered, rectified and low pass filtered by circuits 172,
174, and 176 respectively. The gain of amplifier 170 is increased
when computer 160 detects low amplitude return echoes. The output
of low-pass filter 176 is an envelope of high frequency voltage
return echoes generated by sensors 45 and 46 in sequence. In the
preferred embodiment of the apparatus of this invention,
digitization of envelope signals on lead 177 is accomplished by a
signal processing and sensor firing protocol of computer 200. The
envelope signal on lead 177 is digitized in this manner, rather
than with a conventional A/D converter circuit in order to conserve
scarce electrical power for a down hole measurement during long
time periods of drilling.
The digitizing software and firing pattern provides digitization of
the envelope signal on lead 177 by firing a given sensor (that is,
sensor 45 or 46) N times where N is preferably between 5 and 15.
Each firing is performed with a smaller threshold (or higher gain).
For each gain/threshold combination, a proper delay is set to avoid
noise detection.
FIG. 3B illustrates a firing/echo pattern which is repeated eight
times. Eight counters are provided, each associated with one of the
eight threshold levels. Each counter records the time of a crossing
of its threshold. When a set time is reached (for example 200
microseconds), the processor records the number of threshold
crossings of the envelope signal on lead 177 associated with each
counter. In FIG. 3B, the dots on the signal envelope represent the
position of signal detection. The formation echo amplitude of
crossing C13 is between threshold (1) and (2). Its peak amplitude
is at the time associated with crossing C13. It can be seen that
the envelope signal on lead 177 is digitized by the multiple
firing-multiple threshold technique with multiple counter software
procedure described above.
After digitization, such envelope signals of the echo signals are
processed in computer 160 according to the methods discussed below.
Signals representative of the processing of the envelopes of the
returning signals are stored in module memory 180 or are passed
along to MWD tool 29 for transmission to the surface
instrumentation 7 for further processing.
Delay-line and Borehole Echo Determination
The measurement of standoff and borehole diameter is illustrated
schematically in FIGS. 4 and 5 where transceiver 45 includes
backing element 58, ceramic disk 54, and delay-line 70. A voltage
pulse V of high frequency oscillation is impressed on ceramic disk
54 which responds by emitting high frequency acoustic pulses,
depicted as arrow (1) into delay-line 70. Return echoes are sensed
by ceramic disk 54 and a voltage representative thereof is
impressed on leads 64. Only one timing cycle for a transceiver is
depicted in the illustration.
When the sonic pulse (1) reaches the interface between the
delay-line 70 and the drilling fluid in annulus 10, part of the
sonic pulse is transmitted through the interface and into the
annulus as depicted by arrow (5). Part of the sonic pulse is
reflected back toward the ceramic disk 54 as depicted by arrow (2).
The amplitude of the reflected signal (2) depends on the difference
between the sonic impedance of the drilling fluid and the sonic
impedance of the delay-line 70.
The reflected sonic pulse or "echo" (2) strikes the ceramic disk
54, and excites it. Such mechanical excitation generates an
electrical signal representative of the amplitude and time delay of
the sonic echo. The signal is amplified by the electronic module 22
and applied to the downhole computer 160 as described above. A
first delay-line echo is detected as the pulse (2) of FIG. 5
occurring at time T1 after the emitted sonic pulse depicted as
pulse (1).
Sound waves in delay line 70 bounce back and forth between the
ceramic disk 54 and the drilling fluid of annulus 10. At each
reflection, the amplitude of the sound wave pulse is reduced
because part of the energy is transmitted through the interface and
of course is lost as energy of a reflected pulse. Such echoes
bouncing back and forth are depicted as waves (3) and (4) of FIG.
4. Sonic pulse echo (4) is detected at the amplifier 170 and
computer 160 at time 2T1.
A portion of pulse (1) is transmitted into the drilling fluid of
annulus 10 as depicted by arrow (5). Pulse (5) bounces or is
reflected from the formation 9 interface, and an acoustic pulse
echo (6) travels towards the delay-line 70. Part of the energy of
echo pulse (5) is transmitted into the formation.
Echo pulse signal (6) reaches the delay-line 70 where part of its
energy is transmitted into the delay-line as pulse (7). This pulse
travels through delay line 70 and excites ceramic disk 54. Such
excitation is detected as the amplifier 170 or computer 160 output
(7) at time T2 in FIG. 5.
Multiple echoes can be detected, especially in light drilling fluid
where sonic attenuation is small. An example of a multiple echo is
shown by the sonic pulses as depicted by arrows (8) and (9). FIG. 5
illustrates multiple echo detection of delay-line echoes of pulses
(2) and (4) and of borehole echoes of pulses (7) and (9).
As illustrated in FIG. 1, gas influx bubbles 19 may enter the
drilling fluid in the annulus 10 from formation layers through
which the bit is drilling. Such bubbles flow upwardly by and pass
in front of the transceivers 45, 46. The sonic attenuation and
impedance of the drilling fluid are changed by the gas. The signal
processing of the electronic module 22 of FIG. 3A detects such
changes in the characteristics of the drilling fluid.
FIGS. 6A, 6B to 9A, 9B illustrate several categories of return echo
patterns which are the result of the measurement apparatus
configuration, borehole geometry, cuttings, and gas bubbles in the
drilling fluid. FIGS. 6A, 6B, to 9A and 9B illustrate conditions of
clean mud, cuttings in mud, a small amount of gas in the mud, and a
great amount of gas in the mud, respectively. The FIGS. 6B, 7B, 8B,
9B illustrate the kinds of echo signal returns which are to be
expected from the conditions of FIG. 6A, 7A, 8A, 9A. The "B"
diagrams of the Figures represent the envelope of the voltage
output of the amplifier 170 after rectification of the return pulse
by rectifier 174 of FIG. 3A. Such "B" diagrams are plots of voltage
amplitude versus time. The time reference is from the excitation
pulse (1) which is shown as saturation of the amplifier 170. Such
excitation pulse (1) is masked in the digitization method as
described above in connection with FIG. 3B.
After firing of the excitation pulse represented as pulse (1), an
echo from the front face interface between delay-line 70 and
drilling fluid in annulus 10 is returned to the ceramic disk 54 as
pulse (2). At a later time the formation echo is returned to
ceramic disk 54 as indicated by pulse (3). The excitation voltage
applied to ceramic disk 54 is maintained at a constant level.
Accordingly, the echo amplitudes result from a constant amplitude
emitted pulse.
The amplitude of the delay-line echo (2) depends secondarily on the
attenuation in the matching layers 56 and rubber layer 60 (of FIGS.
2A, 2B, but not illustrated in FIGS. 4, et seg.) and the delay-line
70 . Typically, the attenuation of the matching layer varies
slightly with temperature. But the amplitude of the delay-line echo
(2) depends primarily on the coupling with the drilling fluid,
because the reflection coefficient at the delay-line - drilling
fluid interface is related to the sonic impedance of the fluid. In
other words, ##EQU1## where R.sub.DL is the reflection coefficient,
Z.sub.MUD is the sonic impedance of the drilling fluid, and
Z.sub.DL is the sonic impedance of the delay-line.
The borehole echo amplitude (that is, the echo from the formation
wall of the borehole) depends on several parameters. One such
parameter is the sonic attenuation of the drilling fluid. Sonic
attenuation of the drilling fluid increases nearly linearly with
mud density for a given frequency. Due to this effect, the
formation echo pulse (3) of FIG. 6B may vary by a factor of 100,
with varying standoff distances and mud attenuation.
Another such parameter is the reflectivity R.sub.f of formation
wall. Such wall reflectivity depends on the sonic impedance of the
formation Z.sub.f and the rugosity of the formation. Variation in
borehole wall reflectivity can affect the amplitude of the borehole
echo pulse by a factor of 10.
Another parameter affecting the amplitude of the borehole echo
pulse is the degree of parallelism between the sensor face and the
borehole wall. The amplitude may vary by a factor of 10 due to such
parallelism factor. In other words, the strongest borehole signal,
other factors being equal, results from the transceiver being
perpendicular to the borehole wall.
Other factors affecting the amplitude of the borehole echo include
the delay-line sonic attenuation and the coupling between the
drilling fluid and the delay-line. Such coupling varies with the
density of the drilling fluid (typically it improves with
increasing density) because the mud sonic impedance depends on the
mud density. Each of the factors of delay-line attenuation and mud
delay-line coupling may affect the amplitude of the borehole echo
by a factor of two.
FIG. 7A depicts the situation and effects of drilling cuttings
being present in the drilling fluid. Each cutting reflects part of
the emitted sonic pulse back toward the ceramic disk 54. As a
result, each cutting generates a signal at the output of the
amplifier. Such cutting echoes are depicted as echoes (20), (22) in
FIG. 7B. Their amplitude depends primarily on the size of the
cutting and the sonic attenuation in the mud. With low sonic
attenuation mud, most cuttings typically have signals which are
smaller or equal to the borehole pulse (3). With high sonic
attenuation mud, the borehole echo (3) is attenuated by a larger
ratio than the cutting echoes (20) , (22) because it is always more
distant from the disk 54. In such a case, the borehole echo (3) may
become smaller than the cutting echoes, (20), (22).
FIG. 8A depicts the situation and effects of a small amount of gas
in the mud, which typically is in the form of small gas bubbles 19.
For such a condition the sonic attenuation of the mud increases. As
a result, the amplitude of borehole echo (3) is reduced as
illustrated in FIG. 8B. The delay-line echo (2) varies slightly,
because the mud impedance decreases slightly with a small increase
in gas concentration. Because the delay-line impedance is normally
higher than the mud impedance, the delay-line echo (2) increases
slightly with a small increase in gas concentrated in the mud.
FIG. 9A depicts the case of a large gas concentration of small
bubbles due to a gas influx into the drilling mud in annulus 10.
Large gas concentrations typically are defined as gas fractions
equal to or above 1% of the mud fraction. For such a gas
concentration, sonic mud attenuation may reach 15 db/cm, so that
the borehole echo signal (3) is greatly attenuated. Such small
amplitude of borehole echo (3) may make its detection difficult.
The delay-line echo pulse (2) amplitude increases up to 10% with
the gas concentration in mud.
FIGS. 9C and 9D are similar to FIGS. 9A and 9B, but represent the
case of large gas bubbles in annulus 10 passing sensor 45 on their
way to the upper surface of the borehole. Such large bubbles may
produce an echo as at (4) of FIG. 9D which is of the same relative
absolute amplitude as that of the delay-line echo (2). It has been
found that the phase of a large bubble echo (4) is reversed or
180.degree. out of phase from the phase of other echoes. In other
words the signal (4) of FIG. 9D is a rectified envelope of a high
frequency pulse which is 180.degree. out of phase with other echo
pulses. Phase detector 173 detects such phase shift of the
oscillation signal of the returning echoes and sends a signal to
computer 160 when such a condition is sensed.
The fact of the 180.degree. phase shift of an echo pulse provides a
means for identifying large gas bubble; that is, the phase of each
echo is first determined. If such phase is 180.degree. from that of
the delay-line echo, such echo represents a large gas bubble. For
such a case, a signal is sent to the surface instrumentation under
control of computer 160 via MWD sub 29 so that an alarm may be
generated to alert the driller as to the fact of a large gas bubble
migrating to the surface which has been detected near the bottom of
the borehole.
The stored program 200 of computer 160 has stored therein echo
determination logic for distinguishing borehole echoes and
delay-line echoes from cutting echoes and other spurious echo
signals. Such logic is in part based on the following
considerations.
The formation or borehole wall is the most distant reflector.
Cuttings are always closer to the ceramic disk 54 than is the
borehole wall. Disregarding the case of double echoes, the borehole
echo should always be the last echo.
In most drilling conditions cuttings will always be present in the
path of the sonic beam. The larger the size of the cuttings, the
fewer individual cuttings echoes will be present.
In a drilling fluid of low attenuation, most cuttings produce an
echo smaller than the formation.
In a drilling fluid of high attenuation, it is possible that the
cutting echo signal may be larger than the formation echo signal if
the difference in sonic path length is relatively great.
After the arrival of an echo at the sensor, the sensor noise is
increased by the noise of this echo. Such noise decays to the level
of sensor noise.
Small cuttings (those of less than 1 MM diameter) create an
increase of base line noise, but usually cannot be individually
recognized.
FIGS. 10, 11, and 12 illustrate various conditions that the
processing logic of program 200 considers. The logic flow path of
FIG. 13 outlines the logic steps of the stored program 200.
FIG. 10 illustrates the output of the rectifier 174 (FIG. 3) which
corresponds to the case when several distinct echoes (24), (25),
(26), (28) are detected before the borehole echo (3). The emitted
pulse of ceramic disk 54 is represented as amplifier saturation (1)
which is electronically masked during digitization. The delay-line
echo is the echo (2) .
The logic step 202 of FIG. 13 identifies formation and cutting
echoes occurring after delay-line echo (2). The delay-line echo (2)
is the first echo, where the delay-line 70 has but one interface
with the drilling fluid. The stored program 200 stores the
amplitude and arrival time of each of the echoes occurring after
the delay-line echo. For example, for the echo patterns of FIG. 10,
echoes (24), (25), (26), (28) and (3) are stored.
The logic box 204 of FIG. 13 illustrates that noise echoes are
rejected by requiring that each echo occurring at a certain time
has to be above a minimum signal level for that time. Such
requirement insures the separation of echoes from sensor noise. The
level of acceptance decreases with time after excitation, because
the sensor noise quickly decays after the excitation. In other
words, the amplitude of each echo is compared with a predetermined
function A.sub.min (T.sub.N) where T.sub.N is the echo delay time
after the excitation pulse. The processing preferably recognizes a
limited number of echoes (in the range of 2 to 12). The larger
echoes are saved for further processing. Applying such logic to
FIG. 10, echoes (24), (25), (26), (28) and (3) will be
accepted.
The next logic step depicted as logic box 206 of FIG. 13, insures
that each successive echo has a decreasing amplitude with time. In
other words, the amplitude of each successive echo must be smaller
than that of the previous echo. If not, the previous one is
discarded from the list of echoes. Such processing is based on the
logic that if a large echo comes after a small one, the large echo
corresponds to a larger reflector. Such larger reflector is either
a large cutting or the borehole wall, but the smaller echo coming
first cannot be from the borehole wall. In FIG. 10 the echo (24)
will be discarded based on the criteria of logic box 206 of FIG.
13.
Each echo must be separated in time from each other echo by a
certain predetermined minimum time in order to avoid multiple
detections of the same echo. In FIG. 10, the echo (28) is rejected
by this criteria as being a noise artifact of echo (26). Logic box
208 states the criteria.
The delay-line and borehole echo logic of the invention initially
defines the echo (3) of the illustration of FIG. 10 to be the
"temporary formation echo". It is the last one detected. Before the
final decision that such echo is indeed the borehole echo, two
additional tests are made: first, the echo must not be a double
echo of the echo (26); and second, the echo (3) must not be a noise
echo generated by the echo (26).
If one of these two tests is not passed by echo (3), then it is
rejected and echo (26) (note that echo 28 already has been
rejected) is temporarily defined as the "temporary formation echo".
The same two acceptance tests are again performed for this
temporary formation echo and the immediately preceding echo. If
these tests are successful, the echo (26) is accepted. If not, the
search continues. A final solution always exists, because as above,
the "temporary formation echo" cannot be compared to a previous
echo if it comes immediately after the delay-line echo.
The previous procedure may force a double formation echo to be
accepted as the formation echo. To account for this possibility a
test is performed on two successive echoes. This double echo
acceptance test of the "temporary formation echo" verifies that
this echo delay time is not approximately two times the arrival
time of the previous echo. As illustrated in FIG. 11, the echo (30)
is first accepted as "temporary formation echo". But its arrival
time is equal to about two times the arrival time of echo (3).
Accordingly, echo (30) is rejected, and echo (3) becomes the
"temporary formation echo". Because there is no previous echo after
the delay-line echo, echo (3) becomes the final solution as the
borehole or formation echo. Such logic is illustrated as logic
boxes 210, 212 where the delay time of the temporary formation echo
is compared with twice the delay time of each preceding echo.
The last test that a "temporary formation echo" has to pass
successfully before final acceptance is the test of additional
noise due to a previous echo. Each echo increases the noise in the
sensor after its arrival. This noise decays with time. This noise
level can be above the minimum level for its detection time. This
minimum level is determined for a "quiet" situation. Accordingly,
the formation echo has to be at least above this minimum level,
depending on its delay time for the case of a "quiet sensor". But
in case of previous echo already detected, it has to be above the
noise generated by such echo.
The most simple implementation is to insure the amplitude of the
"temporary formation echo" is above a certain ratio of the previous
echo amplitude. An example is shown in FIG. 12. The echo (32)
represents noise generated by the echo (3). This test rejects the
echo (32), and echo (3) is accepted as "temporary formation echo".
This echo (3) may next be compared to previously occurring echoes
if they are present, to determine which echo is finally accepted as
the borehole or formation echo. Logic step 214 of FIG. 13 describes
this test to determine if an echo is the result of induced sensor
noise.
The amplitude of the finally accepted formation echo is stored
along with its delay time from the emitted pulse and real time for
the measurement. Such step is illustrated in logic box 216 of FIG.
13.
Determination of Standoff and Borehole Diameter
The borehole delay time T.sub.n stored in memory 180 according to
the process of FIG. 13 provides the data necessary to determine
standoff. Standoff is the distance between the front face of
delay-line 70 and the wall of borehole 9. A determination of
standoff and the diameter of the borehole at the depth position of
the transceivers 45, 46 in the drilling string in the borehole
provides valuable information to a driller. Such measurements may
be stored downhole in memory 180 or passed to a MWD tool 29 for
transmission to surface instrumentation 7 (FIG. 1). Both methods
(downhole storage and transmission to the surface while drilling)
may be performed simultaneously. The tool 20 acts as a conventional
drill collar (in that it adds weight on the drilling bit) even
while simultaneously performing the measurements described above
and below.
The time delay of the borehole echo is inversely related to the
standoff of the transceiver 45 or 46 from the borehole wall In
other words, ##EQU2## where V.sub.s =sonic velocity and T is the
measured time delay corrected for the time delay in the delay
line.
Obtaining a numerical value for sonic speed in the above formula
for a determination of Standoff is preferably obtained from a table
for the given pressure and temperature. Sonic speed varies only a
small amount with pressure and temperature in a downhole zone of
interest.
The standoff measurement with one transceiver enables the
statistical evaluation of the hole diameter when the tool is
rotating (which is the normal case during drilling). During the
rotation, the transceiver 45 sends the sonic pulse through the mud
gap between the tool and the borehole wall which may vary as the
tool rotates. The measured standoffs are cumulated for statistical
processing, so that the average hole diameter can be calculated
after several turns. The best rate of measurement is reached when
several standoffs can be evaluated per second. As the typical drill
string rotation speed is between 50 to 200 RPM, an average
accumulation time from 10 to 60 seconds collects enough data for
accurate averaging.
The average hole diameter based on only one transceiver is then
calculated:
The addition of a second transceiver 46 diametrically opposed to
transceiver 45 improves the diameter measurement when the tool
center is not coaxial with the well-bore during drilling.
Transceiver 45 is first used to measure the standoff on its side.
Then immediately thereafter the transceiver 46 is used to measure
the standoff on the other side of the tool. An instantaneous firing
of both transceivers is not required, as long as the tool movement
in the time between the both measurements is small.
With the typical range of drill string rotation speeds, and because
the wave beam width covers several degrees of the well-bore
circumference (due to the diameter of the transceiver and sonic
divergence), the time between the standoff evaluations performed
with both transceivers can be as small as 50 milliseconds. The
smaller the time, the better the final diameter evaluation. The
advantage of non-simultaneous measurements is the reduction of the
size the electronics module 21, because the same system can be
multiplexed to control the different transceivers. The physical
size of the electronics is often a major limitation for MWD type
devices. Furthermore, the multiplexing and the smaller size of the
electronics module required for non-simultaneous measurement
reduces the instantaneous electrical power consumption, which can
be critical when the tool is running from battery 150 of FIG.
3.
An approximation of the nearly instantaneous hole diameter can be
calculated as:
With
Standoff 1=standoff measured with transceiver 45
Standoff 2=standoff measured with transceiver 46 Tool
diameter-distance from face to face of the transceivers 45, 46.
This instantaneous diameter is saved in a vector. After
accumulation time (which typically can be in the range of 10 to 60
sec), the diameter data stored in that vector are statistically
processed to determine statistical parameters such as the average
diameter, the most probable and/or an approximation of the largest
diameter, or various percentiles of a Histogram. Such parameters
are transmitted to the surface (or, alternatively, stored in the
down-hole memory for a later use). With the statistical processing,
the hole geometry determination is less sensitive to false
measurements which can occur during drilling. As explained above,
these false measurements, caused by cutting echoes detection
instead of formation echoes detection, poor formation echo shape
due to the rugosity of the formation, the misalignment of the
sensor with the wall, or by a spike of noise due to the drilling
operations, are eliminated for the most part by the processing
steps of FIG. 13, but inevitably, a few false measurements may pass
such logic processing.
Detection of Gas Influx into the Borehole While Drilling
(1) Assessing the amplitude of delay-line echoes: sonic impedance
of drilling fluid
As illustrated in FIGS. 6 to 12, the delay-line echo (2) is readily
identified due to its occurrence shortly after the termination of
the emitted sonic pulse (1). The amplitude of such delay-line
echoes are stored as a function of time, in a manner similar to the
storage of the borehole echo parameters of logic box 216 of FIG.
13. The amplitude of such delay-line echoes is characteristic of
the reflection coefficient of the delay-line 70 and the drilling
fluid in annulus 10. As explained above, the reflection coefficient
depends on the sonic impedance of the drilling fluid which can be
affected to a large degree by the amount of gas in the drilling
fluid.
When gas enters the drilling fluid, the sonic impedance of drilling
fluid decreases since gas entry reduces the drilling fluid sonic
speed and density. As a result, the sonic coupling between the
sensor delay-line 70 and the drilling fluid in annulus 10 varies
with the reflection coefficient. In most cases, the sonic impedance
of the delay-line 70 is between 2 and 3.5 Mrayls depending on its
material and its operating temperature. It is typically higher than
the sonic impedance of the drilling fluid which is typically
between 1.5 to 3.5 Mrayls. Accordingly, in the usual case were the
delay-line sonic impedance is about 3 Mrayls, the echo of the front
face of the delay-line 70 increases in amplitude with an increase
of gas concentration, because the difference in sonic impedance of
the fluid and that of the delay-line increases.
The broadest concept of the invention is to measure and monitor the
delay-line echo amplitude as a function of time during drilling. In
normal drilling operations, the delay-line echo amplitude drifts
slowly with time due to pressure and temperature changes down-hole.
The sensor performance and the acoustic properties of the drilling
fluid depend on these down-hole conditions. Such drift is small
because down-hole pressure and temperature change slowly while
drilling.
But gas influx occurs relatively suddenly resulting in a sudden
drop (a few percent in a few minutes) of sonic mud impedance. Such
change causes a rapid change of the delay-line echo amplitude.
Monitoring of the rate of change of this amplitude provides a way
to detect down-hole gas influx.
Additional processing can be performed to predict the amount of gas
of the gas influx. This additional processing requires data
concerning the sensor performance under conditions of temperature
and the current mud density. Additional processing can be performed
if the impedance of the delay-line can be measured, so that the
front-face echo amplitude can be converted into mud impedance. Such
delay-line impedance can be measured if the delay-line is
constructed of two layers, so that an echo from the interface
between these two layers can be detected. Assuming constant
thickness of the outermost layer in contact of the fluid, the sonic
speed can be calculated for this layer. The density of the
outermost layer may be assumed to be constant (which is a good
approximation with hard plastic or hard rubber). Then, the
impedance of this layer can be calculated.
2) Assessing borehole echo amplitude: Sonic attenuation of drilling
fluid
From several detected borehole echoes, the mud attenuation can be
calculated by the method illustrated in FIG. 14. A line is fit
between the logarithmic value of the borehole echo amplitude versus
the corresponding standoff. The slope of such line is equal to the
sonic attenuation in the mud.
As long as all other parameters which control the amplitude of the
borehole characteristics such as rugosity, impedance, etc., remain
constant over the time of measurement of the borehole amplitudes,
the slope of the line defined above and illustrated in FIG. 14 is
independent of the values of such parameters.
Among the parameters which affect borehole echo amplitude are the
sensor performance, the excitation voltage, the attenuation in the
delay-line and matching layer, the sonic coupling between the
sensor and the mud, and the reflectivity of the formation. All such
parameters influence the Y-intercept of the fitted line. A
correlation coefficient of the data may be calculated to validate
the fitting of the line L and to provide for the rejection of an
erroneous calculation of mud attenuation.
A method for gas detection is illustrated in FIG. 15, where mud
attenuation is plotted as a function of time. Such method may be
performed by tool computer 160, or it may be performed by surface
instrumentation computers in surface instrumentation 7 after
amplitude data and standoff data have been transmitted to the
surface. When no gas is in the drilling fluid, sonic mud
attenuation is typically in the range of 1 to 5 db/cm. With a small
gas influx, of the range of 0.2% void fraction of the mud, the
sonic mud attenuation jumps dramatically to 8 to 15 db/c m or more
at the basic sensor frequency Accordingly, such gas influx at time
T.sub.INFLUX is detected by the mud attenuation plot of FIG. 15.
Even without a reference measurement, gas influx may be determined
by the change. A mud attenuation reference measurement (measured as
close a possible to down-hole conditions) improves the resolution
of influx detection.
The increase in the mud impedance curve at time T.sub.INFLUX
confirms the determination of gas influx as illustrated by FIG.
15.
Transmission of Signals to Surface Instrumentation for Further
Processing
The parameters identified above, such as standoff, sonic impedance
and mud attenuation may be determined as a function of drilling
time and stored in electronic module memory 180. These data of such
memory 180 as well as others, may be transmitted to surface
instrumentation 7 via MWD tool 29 using the drilling fluid as a
communication path. Such MWD tool and methods are conventional in
the art of MWD communication.
When the mud attenuation and mud impedance signals received by
surface instrumentation 7 simultaneously increase by a
predetermined amount within a predetermined drilling time period,
an alarm may be generated as signified by bell 7A of FIG. 1.
Various modifications and alterations in the described methods and
apparatus will be apparent to those skilled in the art of the
foregoing description which does not depart from the spirit of the
invention. For this reason, these changes are desired to be
included in the appended claims. The appended claims recite the
only limitation to the present invention. The descriptive manner
which is employed for setting forth the embodiments is to be
interpreted as illustrative but not limitative.
* * * * *